Source Rock Characterization and Petroleum ... - Wiley Online Library

doi: 10.1111/j.1751-3928.2011.00163.x

Original Article

rge_163

Resource Geology Vol. 61, No. 3: 270–280

270..280

Source Rock Characterization and Petroleum Systems in North Ghadames Basin, Southern Tunisia Dhaou Akrout,1 Hassène Affouri,2 Riadh Ahmadi,3 Eric Mercier4 and Mabrouk Montacer2 1

Laboratory “Hydrosciences Appliquées” (06/UR/10-03), Higher Institute of Water Sciences and Techniques, University of Gabès, Zrig, Gabès, 2Laboratory of Organic Geochemistry, Department of Earth Sciences, Sciences Faculty, 3Laboratory of Eau, Energy and Environment (LR3E), National School of Engineering Sfax, University of Sfax, Sfax, Tunisia and 4Laboratory of Planetology and Geodynamics (UMR-CNRS 6112), Faculty of Sciences and Techniques, University of Nantes, Nantes cédex, France

Abstract This paper presents geochemical analysis of drilled cutting samples from the OMZ-2 oil well located in southern Tunisia. A total of 35 drill-cutting samples were analyzed for Rock-Eval pyrolysis, total organic carbon (TOC), bitumens extraction and liquid chromatography. Most of the Ordovician, Silurian and Triassic samples contained high TOC contents, ranging from 1.00 to 4.75% with an average value of 2.07%. The amount of hydrocarbon yield (pyrolysable hydrocarbon: S2b) expelled during pyrolysis indicates a good generative potential of the source rocks. The plot of TOC versus S2b, indicates a good to very good generative potential for organic matter in the Ordovician, Silurian and Lower Triassic. However, the Upper Triassic and the Lower Jurassic samples indicate fair to good generative potential. From the Vankrevelen diagram, the organic matter in the Ordovician, Silurian and Lower Triassic samples is mainly of type II kerogen and the organic matter from the Upper Triassic and the Lower Jurassic is dominantly type III kerogen with minor contributions from Type I. The thermal maturity of the organic matter in the analyzed samples is also evaluated based on the Tmax of the S2b peak. The Ordovician and Lower Silurian formations are thermally matured. The Upper Silurian and Triassic deposits are early matured to matured. However, Jurassic formations are low in thermal maturity. The total bitumen extracts increase with depth from the interval 1800–3000 m. This enrichment indicates that the trapping in situ in the source rocks and relatively short distance vertical migration can be envisaged in the overlying reservoirs. During the vertical migration from source rocks to the reservoirs, these hydrocarbons are probably affected by natural choromatography and in lower proportion by biodegradation. Keywords: Ghadames basin, hydrocarbon potential, Rock-Eval pyrolysis, saharan platform, source rock, total organic carbon.

1. Introduction A petroleum system is defined as the natural system that encompasses the geologic elements and processes essential for hydrocarbon accumulation and preserva-

tion (Magoon & Dow, 1994). The essential elements and processes include a petroleum source rock, maturation of the organic material, a migration pathway for the hydrocarbons to a reservoir rock, and a trap/seal (Magoon & Dow, 1994). Each of these elements must

Received 23 December 2010. Accepted for publication 6 January 2011. Corresponding author: D. Akrout, Laboratory “Hydrosciences Appliquées”, Higher Institute of Water Sciences and Techniques, University of Gabès, Zrig, 6072, Gabès, Tunisia. Email: [email protected]

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© 2011 The Authors Resource Geology © 2011 The Society of Resource Geology

Petroleum systems in Ghadames basin, Tunisia

Fig. 1 Location map of the study area and the limits of the Ghadames basin (Underdown & Redfern, 2008).

take place in time and space so that the organic matter can be converted to petroleum and preserved for extraction. A petroleum system exists wherever these essential elements and processes occur together. The study case chosen is Sud Remada permit in Tunisia (Fig. 1). This region is located in the northern part of the Ghadames basin, which itself is part of the Saharan platform. The referred basin is considered as the largest oil province in northern Africa. It also constitutes one of the hydrocarbon mature basins and therefore is one of the most explored petroleum provinces in Tunisia (Achech, et al., 2001). Several studies have been carried out to explain the exceptional oil reserves in this region. Most geological investigations have been concentrated on the reservoirs and traps. Recent studies of Acheche et al. (2001) and Underdown and Redfern (2008) have focused on the characterization of the petroleum system, the investigation of the stratigraphic position and the spatial distribution of thermally mature source rocks in order to assess the timing and distribution of hydrocarbon. Contrarily to the aforementioned studies, the present investigation focuses more on the details of the oil qualitative aspect by the use of organic geochemistry tools i.e. total organic carbon (TOC) and Rock-Eval pyrolysis, as Felhi et al. (2008) concluded for the GafsaMetlaoui basin in south-western Tunisia. Its principal objective is to understand the organic matter types, © 2011 The Authors Resource Geology © 2011 The Society of Resource Geology

their depositional environments, the thermal maturity, and the migration processes and direction.

2. Geological setting Petroleum exploration permit Sud Remada is located in the extreme southern Tunisia (Saharan platform) and in the Ghadames basin (Fig. 1). This sedimentary basin is a large depression on the North African platform encompassing more than 350 000 km2 over western Algeria, southern Tunisia and north-eastern Libya (Van de Weerd & Ware, 1994; Rudkiewicz et al., 1997; Echikh, 1998; Klett, 2000). The Ghadames basin is characterized by a particular tectonic and stratigraphic evolution (Alem et al., 1998; Echikh, 1998). This area is characterized by the following tectonic history; A regular subsidence during the Paleozoic, followed by the Hercynian compressive event responsible for the uplift and erosion of the Telemzane arch. Consequently the Palaeozoic series was overlain with regional and angular unconformity by the Mesozoic sedimentary rocks (Acheche et al., 2000). Finally, thin Neogene sandstone covered these series with a second major regional unconformity, lacking in Paleogene rocks. Several Palaeozoic formations and especially the Triassic sandstone (TAGI Formation) are known to be the target reservoirs for hydrocarbon explorations in the

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Fig. 2 Lithostratigraphic column of the studied well in southern Tunisia and sample positions. The location of drill hole is shown in Figure 1.

Saharan Platform (Underdown & Redfern, 2008). The main oil productive reservoirs are from shallowest to the deepest: (i) TAGI sandstone, middle Triassic, (ii) Acacus Formation (B and A), middle Silurian, and (iii) the El Hammra sandstone (Ordovician).

3. Materials and methods 3.1 Material For this study, a total of 35 drill-cutting samples were selected from different depths and formations (Fig. 2). Samples from the depths up to 1200 m have been drilled by using water based mud, while, samples from the depths deeper than 1200 m are contaminated by oil-mud. The cuttings were the subject of several geochemical analyses and microscopic observations.

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3.2 Organic geochemical analysis 3.2.1 Cutting preparation The cuttings, contaminated by either oil or water-mud, have undergone several specific procedures to avoid the influences of the geochemical analysis (Fig. 3). The samples drilled with water-based mud were washed carefully with water over sieves in order to remove the mud and all other soluble pollutants. After washing only debris smaller than 5 mm are kept. This precaution is used to eliminate carvings that could be dropped from depths other than the drilled sample. After washing, the samples are kept in humid form to prevent their exposure to high air temperature, which might artificially increase their thermal maturation. The cuttings drilled with oil-based mud are dried at low temperature and washed with chloroform to eliminate the fuel oil (Bordenave, 1993). © 2011 The Authors Resource Geology © 2011 The Society of Resource Geology


Fig. 3 Standard cuttings preparation procedure for screening analyses.

3.2.2 Rock-Eval pyrolysis The Rock-Eval II pyrolysis has been performed on the whole set of samples using the reservoir mode (temperature heating ramp: 10°C min-1). Besides the classical S1 peak (lith thermovaporizable fraction), this specific mode allows deconvolution of the S2 peak into S2a and S2b peaks, which can be assigned to a heavy thermovaporizable fraction and to an actual pyrolyzable fraction, respectively (Trabelsi et al., 1994) (Fig. 4). The residual organic carbon is oxidized and the resulting CO2 is recorded as S4 peak. The total organic carbon (TOC) is calculated from the entire set of generated peaks (Espitalié et al., 1985a). These analyses were undertaken in the Organic Geochemistry Laboratory from “Entreprise Tunisienne d’Activités Pétrolières” (E.T.A.P). Rock-Eval Tmax (°C) is the temperature at the maximum S2b (pyrolysable hydrocarbons, mg HC/g rock) as a function of the thermal maturity (Espitalié et al., 1984; Peters, 1986; Tissot et al., 1987). The hydrogen index (HI) and the oxygen index (OI) are derived from the S2b and S3 parameters, respectively, by normalization to the organic carbon content. The production index (PI) (transformation index) is given by (S1 + S2a)/(S1 + S2a + S2b) (Espitalié et al., 1977). 3.2.3 Bitumen analysis The bitumen from powdered samples (30–40 g) was extracted using dichloromethane as solvent (300– © 2011 The Authors Resource Geology © 2011 The Society of Resource Geology

Fig. 4 Rock-Eval analysis of cutting sample using the “reservoir mode” heating program.

400 cm3) for 1 h at 40°C. After that, the filtrated solvent was evaporated (rotary evaporation with water aspirator and evaporation temperature 40°C). Then the extract was concentrated by allowing the oil-solvent solution to stand at room temperature until the CH2Cl2 is removed. Organic extract (C0) was fractionated by a chromatography column (42 ¥ 1.2 cm i.d) using silica gel (Blumer, 1957, Fazeelat and Yousaf, 2004). Aliphatics (F1), aromatics (F2) and polar (F3) fractions, were then

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Table 1 Total organic carbon (TOC) and Rock-Eval pyrolysis results of cutting samples from OMZ-2 oil well in the Ghadames basin Age

Jurassic

Formation name

Sbaia

Abreghs

Horizon B Triassic

Bou Sceba

Azizia

Silurian

R.hamia Acacus

Tannezuft Ordovician

Tartard Kasba

Hammra Sanghar

Sample

Sb1 Sb2 Sb3 Sb4 Sb5 Abg1 Abg2 Abg3 Abg4 Abg5 Abg6 Hb1 Hb2 BSc1 BSc2 BSc3 BSc4 Az1 Az2 Az3 RH A1C A2C A1B A2B A1A A2A Tnz1 Tnz2 Btr Klg1 Klg2 Klg3 Hm Snhr1

S2a

S1 + S2a

Depth

TOC

S1

(m)

(%)

mg HC/g Rock

465 518 580 695 799 850 869 877 909 970 1035 1280 1287 1576 1615 1640 1660 1710 1745 1805 1866 2010 2040 2080 2115 2190 2259 2441 2490 2846 2892 2918 2921 2989 3050

0.44 0.52 0.64 0.10 0.62 0.18 0.29 0.15 0.12 0.09 0.05 1.13 0.64 0.6 0.84 0.89 1.18 1.36 1.19 0.37 1.96 2.24 1.04 1.00 3.78 3.39 1.54 1.56 1.22 2.71 1.52 1.56 1.48 2.74 4.75

0.55 0.24 0.44 0.03 0.16 0.05 0.07 0.06 0.04 0.13 0.04 16.43 4.8 10.49 6.71 14.36 10.82 9.57 37.24 33.67 19.95 34.32 47.08 61.91 17.03 22.34 42.02 34.68 36.42 9.14 47.06 46.52 43.35 22.72 15.26

0.17 1.08 0.2 0.26 1.76 0.16 0.36 0.08 0.15 0.19 0.12 12.8 4.99 5.7 7.06 7.4 10.6 9.95 6.73 3.3 15.8 21.9 6.41 5.62 11.8 37.6 14.7 15.4 11.4 25.2 14.7 14.7 5.67 28.3 53.1

0.72 1.32 0.64 0.29 1.92 0.21 0.43 0.14 0.19 0.32 0.16 29.32 9.79 16.19 13.77 21.76 21.45 19.52 43.97 36.97 35.77 56.29 53.49 67.53 28.88 59.99 56.73 50.17 47.84 34.32 61.81 61.24 49.02 51.05 68.38

S2b

S3

PI

HI

OI

(%) 0.1 0.55 0.32 0.37 0.66 0.48 0.88 0.77 0.4 0.56 0.33 3.29 0.33 0.3 1.12 2.54 1.62 2.32 8.75 5.44 6.54 8.02 8.77 8.94 7.14 7.97 7.04 6.96 6.52 2.25 8.42 8.57 6.39 9.47 10.2

2.35 1.3 1.91 0.01 2.49 1.85 1.8 0.88 0.57 0.57 0.49 0.56 1.43 1.6 1.44 1.01 1.21 3.17 1.02 1.62 0.93 1.88 0.88 1.28 1.21 1.55 1.73 1 1.33 0.61 1.72 0.91 1.09 1.7 1.49

67 13 46 5 6 7 5 7 7 18 8 50 47 64 45 59 47 44 71 79 47 53 76 81 47 33 66 61 67 25 67 67 78 38 19

Tmax (°C)

23 105 50 383 106 273 303 510 324 605 671 291 52 50 133 285 138 170 738 1468 334 357 845 891 189 235 456 447 532 83 554 548 433 346 215

539 248 30 10 401 1052 619 583 462 616 997 50 224 267 171 1 103 233 86 437 48 84 85 128 32 46 112 64 109 23 113 58 74 62 31

425 435 433 429 435 435 426 435 431 441 414 594 414 427 435 440 437 436 431 433 429 433 435 433 440 435 414 436 437 441 433 439

S3 (mg CO2/g Rock); HI (hydrogen index) (mgHC/gTOC); OI (oxygen index) (mg CO2/g total organic carbon [TOC]).

obtained. Only two fractions from bitumen were eluted by a hexane (F1) and a mixture of hexane/ dichloromethane (65:35 Vol/Vol) (F2). F3 is deduced by the following equation: F3 = C0 - (F1 + F2).

4. Results and discussion 4.1 Source rock evaluation 4.1.1 Hydrocarbon potential The TOC content in sediment is an indicator of the total amount of organic matter presents in the sediment (Ronov, 1958). It is expressed as a weight percent of the total rock. TOC values of cutting samples are listed in

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Table 1. Most of the Ordovician, Silurian and Triassic samples contain high TOC contents, ranging from 1.00% to 4.75% with an average value of 2.07%. These values indicate a good to very good generative potential according to the Peters scale (Table 2). On the other hand, TOC contents in samples from the Upper Triassic and the Lower Jurassic range from 0.64% to 1.13%, which indicate fair to good generative potential. However, Peters and Cassa (1994) point out that TOC is not always a good indicator of source rock potential because measurements may include inert carbon that has little or no generating potential. The two aforementioned authors believe that the S2 measurement derived from pyrolysis analysis is a better indicator of © 2011 The Authors Resource Geology © 2011 The Society of Resource Geology


Table 2 Source richness interpretation from total organic carbon (TOC) weight percentage (Peters, 1986) Richness

TOC (Wt.%)

Poor Fair Good Very good

0.0–0.5 0.5–1.0 1.0–2.0 >2.0

Fig. 6 Hydrogen index versus oxygen index diagram with indications for diagenetic evolutionary pathways for type I, II and III organic matter (Espitalié et al., 1977). Plots of the cuttings samples from the studied well (OMZ-2) southern Tunisia. Fig. 5 Plot of total organic carbon (TOC, wt %) versus remaining hydrocarbon potential (S2, mg HC/g rock), showing the source rock generative potential.

the generative potential of source rocks. The plot of TOC versus S2b has been established in order to get an idea about the quantity of organic matter present and its associated hydrogen. For instance, the set of data shown in Figure 5 confirms that the great majority of Ordovician and Silurian samples are good to very good generative potential and the Triassic samples range from fair to good generative potential and finally Jurassic rocks show a poor generative potential. 4.1.2 Organic matter type The Van Krevelen plot of hydrogen index (S2b/TOC ¥ 100) versus oxygen index (S3/TOC ¥ 100) was used to classify the dominant type of organic matter in potential source rocks (Tissot and Welte, 1978; Bordenave, 1993, Fig. 6). Most samples from the Ordovician and Silurian strata show high hydrogen index and low oxygen index. This suggests that the organic matter in © 2011 The Authors Resource Geology © 2011 The Society of Resource Geology

the shale samples contains predominantly Type II marine kerogen, with minor contribution from Type I (oil prone) organic matter. However, the Triassic and Jurassic organic matter is dominantly Type III kerogen, with minor contribution from Type I (Figs 6, 7). 4.1.3 Thermal maturity The thermal maturity of organic matter in the analyzed samples is also evaluated based on the Tmax of the S2 b peak. The maturation range of Tmax varies with the different types of organic matter (Tissot & Welte, 1984; Espitalié et al., 1985b; Peters, 1986; Bordenave, 1993). The range of variation of Tmax is narrow for Type I kerogen, wider for Type II and much wider for Type III kerogen due to the structural complexity increasing of the organic matter (Tissot et al., 1987). In our case of study, the pyrolysis Tmax values for the Ordovician and Lower Silurian samples range from 433°C to 441°C, indicating a mature organic matter (Table 1). Samples collected from the Upper Silurian belonging to the Acacus Formation and from Triassic deposits show Tmax

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values ranging between 429°C and 433°C. This range of variation indicates an early mature to mature organic matter. However, Jurassic samples exhibit the lowest Tmax values, varying from 425°C to 435°C, which suggests low thermal maturity. However, the Azizia and Horizon B Formations are distinguished by Tmax of

441°C and high TOC. These values highlight a source rock that has already passed the “diagenesis sensu stricto” and reached the oil window. On the other hand, some samples show abnormally low Tmax values (~415°C) and abnormally developed S1 peak with regard to TOC and the S2b. This is explained by the probable contamination resulting from drilling mud and/or impregnations (Tissot & Welte, 1984; Peters, 1986; Hunt, 1996).

4.2 Petroleum system

Fig. 7 Hydrogen Index values versus maximum pyrolysis temperature (Tmax) of samples analyzed.

For the samples collected from depth intervals from 500 to 1035 m, the drilling is carried out by using waterbased mud. Subsequently, the cuttings were not contaminated by the oil-mud. These samples, however, show high values of (S1 + S2a/S2b) ratios and PI (around 0.8), and low TOC values (not exceeding 0.5 %) (Fig. 8). Therefore, it is concluded that additional hydrocarbons are present in the sedimentary rocks and majority of them may have been derived by vertical hydrocarbon migration. On the other hand, samples from the 1280 to 2259 m depth interval have an average TOC value of 2% and

Fig. 8 Lithologic section and geochemical log for the oil Well OMZ-2.

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high values of (S1 + S2a) and S2b. The Tmax values range from 431°C to 440°C and PI reached the highest values (0.9). These results support the trapping and the accumulation of hydrocarbon generated from both this rock’s interval and that of deeper source rocks. In addi-

Fig. 9 Lipid extracts versus total organic carbon of cuttings samples from OMZ-2, oil potential raging from 1, poor; 2, fair; 3, good; 4, very good; 5, excellent.

tion, in this interval, some samples are the low Tmax values (=414°C) and the (S1 + S2a/S2b) ratio are higher than 10. This result indicates the possible contamination by the drilling fluid. To test this hypothesis, lipid extract was plotted versus the TOC for all samples (Fig. 9). The samples contaminated by oil mud show very good oil potential. Whereas, the samples without contamination have a low to very low potential. This configuration in two main groups indicates the effect of drilling mud contamination and oil migration. The mature zone from the 2550 to 3050 m depth is formed by the Ordovician and Silurian formations. This zone shows the Tmax values higher than 435°C and high values of (S1 + S2a), S2b, PI and the (S1 + S2a/S2b) ratio. These high values of geochemical parameters suggest that these source rocks have generated and expelled during primary and/or secondary migration of their hydrocarbons to the overlying levels. This hypothesis is confirmed by the dominance of the polar compounds in same maturity levels (Table 3). The values of Pr/Ph, Pr/n-C17 and Ph/n-C18 for analyzed crude oil samples are given in Table 4. Pr/Ph ratios were used to assess the depositional environment (Brooks et al., 1969; Powell & McKirdy, 1973; Didyk et al., 1978). In this study, representative samples

Table 3 Extract yields and relative percentage of saturated hydrocarbon, aromatic hydrocarbon and asphaltic compounds of the studied cuttings sample from the well OMZ-2 Age

Jurassic

Formation name

Sbaia

Abreghs

Triassic

Silurian

Ordovician

Bou Sceba Azizia R.hamia Acacus

Tannezuft Tartard Kesba Leguine Hammra Sanghar

Sample

Sb1 Sb3 Sb5 Abg1 Abg3 Abg4 BSc2 Az1 Az2 RH A(1)C A(1)B A(2)B A(2)A Tnz2 Btr Klg2 Klg3 Hm Snhr1

Depth

Total extract

Aliphatic HC (F1)

Aromatic HC (F2)

(m)

(mg g-1)

Percentage of three fractions

465 580 799 850 877 909 1615 1710 1745 1866 2010 2080 2115 2259 2490 2846 2918 2921 2989 3050

0.35 0.14 0.2 0.06 0.22 0.08 9.56 18.66 37.69 33.9 45.49 54.79 51.79 47.91 45.75 32.46 59.77 29.69 25.31 6.61

24 10 4 17 9 8 27 30 47 44 45 21 40 66 19 47 49 27 21 8

50 15 4 61 84 85 12 13 13 12 11 11 14 13 7 10 10 1 5 3

Asphaltic (F3)

F1 + F2

26 75 92 22 7 7 61 57 40 44 44 68 46 21 74 43 41 72 74 89

74 25 8 78 93 93 39 43 60 56 56 32 54 79 27 57 59 28 25 11

F, fraction (mg g-1 dry weight).


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Table 4 Straight chain alkane and acyclic isoprenoid for the representative samples from well OMZ-2 Age

Formation

Sample

Depth (m)

Pr/Ph

Pr/nC17

Ph/nC18

Jurassic Triassic

Horizon B Azizia Ras Hamia Acacus

Hb1 Az2 RH A(1)C A(2)B A(2)A Tnz1 Tnz2 Klg2 Hm Snhr1

1280 1745 1866 2010 2115 2259 2441 2490 2918 2989 3050

0.85 0.87 0.79 0.86 0.86 0.87 0.89 0.85 0.89 0.65 0.74

0.28 0.51 0.47 0,48 0,58 0.59 0.48 0.3 0.51 0.35 0.28

0.36 0.59 0.58 0,58 0,59 0.68 0.56 0.35 0.58 0.5 0.35

Silurian

Tannezuft Ordovician

Kesba Leguine Hammra Sanghar

probably due to the effects of natural chromatography (geochromatography) and not biodegradation.

5. Conclusion

Fig. 10 Relation between isoprenoids and n-alkanes showing source and depositional environments.

analyzed from the Ordovician, Silurian, Triassic and lower Jurassic strata show low values of the Pr/Ph ratios. These values are much less than 1.0, which indicates reducing conditions of the sedimentary rocks. The plot Pr/n-C17 versus Ph/n-C18 (Fig. 10) shows that samples are trending to the maturation pole. Therefore, we can distinguish two groups: (i) the first group characterized by Pr/n-C17 ratios > 0.48; and (ii) the second group characterized by Pr/n-C17 ratios < 0.3. The Hm sample is observed in an intermediate position between these two groups. This distribution indicates in situ trapping of saturated hydrocarbons. In addition, the Pr/n-C17 and Ph/n-C18 show two cycles of increase according to burial depth (Fig. 11). The first cycle, starts from 3050 to 2918 m in Ordovician formations, while the second is interested in the depth of 2490 (Tannezuft) to 1745 m (Azizia). This evolution is

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The main conclusions of this work are summarized as follows. The Ordovician and Silurian formations are good to very good generative potential source rocks in terms of COT and S2b contents. However, Triassic and Jurassic formations display a fair to good and poor generative potential, respectively. The organic matter deposits in the Ordovician and Lower Silurian is predominantly Type II marine kerogen. However, the Triassic and Jurassic organic matter is dominantly type III kerogen with minor contributions from Type I. The thermal maturity of organic matter in the analyzed samples is also evaluated based on the Tmax of the S2 peak. The Ordovician and Lower Silurian formations are thermally matured. The Upper Silurian belonging to the Acacus Formation and Triassic deposits are early matured to matured. However, Jurassic formations are low in thermal maturity. The Upper Silurian and Triassic formations (2259– 1745 m) have a very good oil potential (free hydrocarbon) and high potential index (PI). These results suggest the trapping and the accumulation of hydrocarbon generated from both the rocks of this interval and deeper source rocks. The total bitumen extracts show enrichment at the level deeper than 1200 m, especially in the 1800– 3000 m interval, in which total bitumen extracts reached a significant rate. This enrichment indicates that there is in situ trapping of hydrocarbons and/or a short distance of vertical migration to the overlying reservoirs. During their vertical migration from the © 2011 The Authors Resource Geology © 2011 The Society of Resource Geology


Fig. 11 Stratigraphic log and Pr/Ph-Pr/nC17-Ph/nC18 variations with depth in OMZ-2 oil well.

source rocks to the reservoirs, these hydrocarbons are probably affected by geochromatography and some biodegradation.

Acknowledgments This work was supported by Research Unit: Geoglob (code: 03/UR/10–02), Science Faculty of Sfax. The Authors are thankful to Moncef SAIDI and Halima bekir-INOUBLI (Tunisian Company of Petroleum Activity) for Rock-Eval pyrolysis. Our special thanks go to Yasushi Watanabe, PhD, for the helpful comments and suggestions that improved this paper.

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